After drilling a hole through a subsurface formation and determining that the formation can yield an economically sufficient amount of oil or gas, a crew completes the well. During drilling, completion, and production maintenance, personnel routinely insert and/or extract devices such as tubing, tubes, pipes, rods, hollow cylinders, casing, conduit, collars, and duet into the well. For example, a service crew may use a workover or service rig to extract a string of tubing and sucker rods from a well that has been producing petroleum. The crew may inspect the extracted tubing and evaluate whether one or more sections of that tubing should be replaced due physical wear, thinning of the tubing wall, chemical attack, pitting, or another defect. The crew typically replaces sections that exhibit an unacceptable level of wear and note other sections that are beginning to show wear and may need replacement at a subsequent service call.
As an alternative to manually inspecting tubing, the service crew may deploy an instrument to evaluate the tubing as the tubing is extracted from the well and/or inserted into the well. The instrument typically remains stationary at the wellhead, and the workover rig moves the tubing through the instrument's measurement zone.
The instrument typical measures pitting and wall thickness and can identify cracks in the tubing wall. Radiation, field strength (electrical, electromagnetic, or magnetic), and/or pressure differential may interrogate the tubing to evaluate these wear parameters. The instrument typically samples a raw analog signal and outputs a sampled or digital version of that analog signal.
In other words, the instrument typically stimulates a section of the tubing using a field, radiation, or pressure and detects the tubing's interaction with or response to the stimulus. An element, such as a transducer, converts the response into an analog electrical signal. For example, the instrument may create a magnetic field into which the tubing is disposed, and the transducer may detect changes or perturbations in the field resulting from the presence of the tubing and any anomalies of that tubing.
While the instrument can provide important and detailed information about the damage or wear to the tubing, this data can be manipulated in a number of ways which limit its usefulness. For example, the speed of insertion or extraction of the tubing segment can have profound effect on the data retrieved by the instrument. For instance, if the same tubing section is pulled though the instrument at two widely varying speeds, the wear data will not be consistent, thus leaving open the opportunity for improperly determining the remaining life for that tubing section.
In addition, grading of the tubing sections is typically accomplished by an operator viewing the data obtained by an instrument. The entirety of the data may include data obtained at several different speeds, thus providing the operator with no possibility of providing an accurate grade to the tubing. Furthermore, since the conventional method of grading the tubing requires an operator to analyze the data, different operators typically grade the same data in different ways, thus providing inconsistent grading across multiple stands of tubing.
To address these representative deficiencies in the art, what is needed is an improved capability for evaluating tubing. For example, a need exists for a method of maintaining a consistent speed of removal of the tubing section during analysis to ensure consistent analysis data. Another need exists for a method of setting the speed of removal or insertion of a tubing section based on the type of tubing and the sensors being used to ensure the most accurate analysis of the tubing sections. A further need exists for a method of parsing the analysis data and displaying only that data that was obtained within the optimal speed range. A capability addressing one or more of these needs would provide more accurate, precise, repeatable, efficient, or profitable tubing evaluations.